The present invention relates to the production of liquid hydrocarbons, and more particularly to the production of liquid hydrocarbons using various thermal methods.
The enhanced recovery of oil, and particularly heavy crude deposits, has increased during recent years as a result of decreasing reserves and increasing prices. These factors have increasingly made thermal recovery methods more and more economically attractive.
In thermal recovery processes using steam, two methods are primarily used. In the first, steam is injected into the formation for a period of time, after which the well is shut in and allowed to soak. Following the soaking period, the crude oil that accumulates in the well is produced, and the process is repeated. In the second method, the steam is used not only to heat the formation, but also to drive the crude toward a producing well. In both of these methods, the steam flows through perforations in the casing in the injection well, and it is thus highly desirable to know the injection profile of the steam entering the formation. That is, a steam injection/thermal recovery program is based upon a predetermined pattern (usually uniform) of steam entry into the formation. It is accordingly important to know whether or not the steam is entering as desired, and not bypassing one or more portions of the formation. It is also desirable to know the quality (liquid/vapor ratio) of the steam being injected into each portion of the formation, since this tremendously affects the amount of heat actually being transported into the formation and into the crude oil deposits therein.
In U.S. Pat. No. 4,581,926 (U.S. application Ser. No. 671,657, filed Nov. 15, 1984), mentioned above, a substantially improved method and apparatus are disclosed for downhole measurements of the quantity and quality of steam being injected into a well. When used with multiple perforation zones, that invention provides a direct means for determining the amount of thermal energy flowing into each zone. The invention thus represents a substantial improvement over prior art methods and apparatus. However, typical injection regimes involve multi-phase flow. That is, a mixture of steam (vapor) and steam condensate (liquid) at temperature-pressure equilibrium is flowing through the well toward and into the formation. This gas-liquid flow stream presents unique challenges from the standpoint of the actual phase distribution therein. That is, at any given location, particularly in wells which may be even slightly deviated, it is oftentimes not safe to infer homogeneity of the phases. Rather, it is entirely possible that the bulk of the liquid may be cascading down the wall of the well along one (usually the lower) side thereof.
In such a case, two problems become immediately apparent. First, a method and apparatus such as disclosed in the above-noted '926 patent ('657 application), which implicitly assumes a fairly homogeneous phase flow, may produce a consequent error. That is, because it intercepts a fractional part of the flow which is taken to fairly represent the whole, then to the extent that the flow is inhomogeneous, the amounts of each phase which are reported in toto may be affected accordingly. Secondly, a heavy wash of liquid across the perforations through which the steam is being injected will result in a much higher proportion of liquid being injected than would be anticipated assuming homogeneity of the phases. Since the heat content of the liquid phase is far less than the vapor phase, the heat injection profile which is calculated will be skewed to that extent.
A need therefore remains for an improved method and apparatus for measuring the steam liquid/vapor profile, particularly where that profile at any given point in the well may not be homogeneous.